The process of awarding petroleum rights should continue.

Jay PARK Managing Director PARK ENERGY LAW

Mexico’s oil and gas approach

April 11, 2018

Jay Park, managing partner of Park Energy Law, talks to TOGY about his work advising oil and gas companies and state players such as Mexico’s Pemex, the best approach to local content and how licensing landscapes worldwide impact investment. Park Energy Law is an international energy firm that has advised companies and states in more than 50 countries.

On private participation: “Private investment in oil and gas makes sense. You just need to do it the right way. States should have private parties do the risk-taking and then properly tax the success cases in a way that makes investment attractive, but also benefits the state in terms of the economic rent it is entitled to receive as owner of the resource.”

On the right tools: “My view is that states should expand the types of contracts they use and the types of fiscal arrangements that they have available to suit the different opportunities.”

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What is the background of Park Energy Law?
Park Energy Law was set up in 2013 following my retirement from Norton Rose Fulbright. I had worked for 33 years as an oil and gas lawyer based in Calgary for a firm called Macleod Dixon. That firm merged into Norton Rose Fulbright in 2012, and then I left it in 2013 to set up my own firm.
My practice, throughout that period from 1980 on, has been focused on oil and gas, and the latter half of that time on international oil and gas, meaning I have been advising oil companies, governments and state oil companies in connection with upstream oil and gas investment projects. That work has occurred now in more than 50 countries around the world.
Our practice is somewhat unique from other firms that do international work because we act for oil companies, states and state oil companies.

Is there a “Chinese wall” when it comes to oil-centric legal practices?
There is, on a country-by-country basis. We don’t act within a country for both the government and investors. In certain countries – 17 of them now – I have advised states and state oil companies. In many other countries, I have advised investors. I think this gives us a unique perspective in advising our clients of both types, because we see the issues and concerns of both sides involved in the typical upstream investment projects.
Also, the extent and breadth of the background I have had in what’s now 38 years of international oil and gas practice is to be able to bring experience from some jurisdictions that has not been seen in others.
To give you an example, one of our largest current clients is Pemex, the state oil company of Mexico. As a result of recent petroleum reforms in Mexico, Pemex is now permitted to enter into joint venture agreements with other oil companies, including farm-outs. Between its formation in 1938 and 2016, Pemex had never done a farm-out.
We assisted Pemex in the Trion farm-out project, which had a highly successful outcome, with an award in December 2016 to BHP Billiton, and with an expected investment in the order of USD 11 billion with Pemex carried for the next USD 2 billion of investment.
They were pleased; we were pleased. It was great to be able to bring the experience of joint ventures and farm-outs from all the many jurisdictions where Park Energy Law has worked and help Mexico develop and negotiate a very good one that is suitable to the country. Following Trion, Pemex has completed two more farm-outs, and they’re embarking on what’s said to be more than a dozen more such transactions.

How was Pemex’s first farm-out conducted?
Mexico’s hydrocarbons reforms, under the hydrocarbons revenue law, mandated a unique approach to doing a farm-out. We adapted international experience with farm-outs to the distinct circumstances of Mexico’s hydrocarbons law and the fact that this was going to be a farm-out conducted under a bidding process, which is unique.
This was a public, international bidding process in which Pemex did not get to select who its farmee would be – it would be the party that bid the largest amount of carry. It was also a deepwater farm-out, and so we needed to apply lessons learned from deepwater joint ventures in other jurisdictions.

How would you characterise the current period in the oil and gas industry?
The recent downturn has been one of the longest I have seen. In terms of comparing it to others, it feels much like 1986, when the price of oil went so low that some did not see a future for the industry outside of the Middle East. I don’t think people believe that that’s going to be the future now, but the concept of lower for longer is definitely where companies are thinking now.
For investment to start coming back to a level at which we’re going to restore investment and start finding oil and gas at the pace that we’re producing and consuming it, prices are going to need to be higher. It has been said that the cure for low oil prices is low oil prices. Hopefully that statement is going to prove true again this time.

Why has the level of mergers and acquisitions been relatively low during this downturn, even though we have seen a number of assets in distress and companies struggling to make ends meet?
Looking at other downturns, there was a lot of M&A. In that sense, this case is also reminiscent of 1986, when there was very limited M&A because, in my view, no one could find the right price for oil and gas assets. Vendors said the current price cannot be the long-term price; it’s going to be higher, so the vendors would demand a price higher than the then-current price.
Buyers said, “Well, we don’t know when the price is going to be higher, so all we can offer you is the current price.” There was no consensus on value between buyers and sellers, and consequently, very few transactions happened.
In other downturns, transactions happened despite low prices, but often there were pressures such as large amounts of debt that forced people to sell in circumstances where they otherwise might try to avoid it. I don’t see as much of that happening now. My sense is that those who can wait it out are waiting it out, and those that have the money to invest are waiting to see signs that the price is going to rise.


Yet we see great successes in the case of Pemex and Mexico, with the Trion farm-out being a case in point. Why is this?
True. Mexico is a special case in the sense that reform was necessary, their production was in decline and they needed new investment and new technology to try to restore it. Circumstances created an incentive to make the changes and commit the state to a new hydrocarbons regime and adopt the concept of allowing private investment in oil and gas activities as in so many other countries around the world – basically every country except Saudi Arabia and Kuwait.
Private investment in oil and gas makes sense. You just need to do it the right way. States should have private parties do the risk-taking and then properly tax the success cases in a way that makes investment attractive, but also benefits the state in terms of the economic rent it is entitled to receive as owner of the resource.

What is the most pressing unfinished item in Mexico’s ongoing reform process?
The reform process means basically creating the full set of rules for oil and gas investment. I sometimes characterise oil and gas activities and petroleum regimes related to them as being like a game of football: You need a playing field, a set of rules, players and a good referee who applies the rules. Mexico is the new field. It has created most of the rules, but not all of them. They need to finish with the rules.
What’s principally missing now is an effective method for facilitating midstream activities and allowing investors in the upstream to get their product to market. Also, the process of awarding petroleum rights should continue, and farm-outs by Pemex should accelerate, as they are planning to do. I look at Mexico as a shopkeeper with wonderful goods, but many of them are still in the warehouse and very few are on the shelf.

Of the five main investment tools that can be utilised in the oil and gas industry, which is dominant today?
Dominance of types of hydrocarbons contracts – concessions, joint ventures, production-sharing contracts, service contracts and hybrids – tends to vary by continent. Europe and North America mostly have concessions. Africa mostly has production-sharing contracts; it is the same with much of Asia. Latin America is quite a mix of different types.
Those different types of petroleum grants are really designed for different types of petroleum opportunities. I’ve often said to states, when they are developing their petroleum regime, that they should have a toolbox with all the tools in it. If all you have is a production-sharing contract, and that is not necessarily well suited to a particular type of exploration and development opportunity, then you lack the required tool.
My view is that states should expand the types of contracts they use and the types of fiscal arrangements that they have available to suit the different opportunities. The example I like to use is that of a cow. A cow has many different cuts of beef: the steak, the sirloin, the top loin – that’s the best part. But there’s also the chuck and the brisket and the shank. We eat the whole cow, but we use different recipes to cook the different parts. The chuck gets ground up into ground beef and eaten at McDonald’s as hamburgers. The brisket is cooked low and slow over a barbecue. If you tried to cook a piece of brisket as though it were a steak, you wouldn’t get a satisfying meal.
I think it’s much the same with oil and gas resources, that the steak of a petroleum “cow,” if you can imagine such a thing, is conventional, sweet, light oil and gas. But there are now many other resources that technology and economics make worthwhile. There are oil sands, coal bed methane, ultra deepwater. You need to design a petroleum regime suited for each of those resources.
When I say a petroleum regime in this respect, I mean the set of rules relating to the fiscal terms, the tenure terms and the environmental rules. Shale, for example, requires a special set of environmental rules for fracking, and if you have that set of rules, you can frack and develop shale on a safe and commercial basis.
In my home jurisdiction, Alberta – I’m a Canadian, from Calgary – we have five different petroleum regimes for conventional oil, conventional gas, heavy oil, oil sands and coal bed methane. Those are the five types of petroleum cow cuts that we have in Alberta. Other jurisdictions aren’t doing that and they need to.

Are there any examples of emerging oil frontiers that have this kind of open mind and are already prepared to deploy all these tools?
Intriguingly, Mexico does allow for all five types, and they have even created a new one called a profit-sharing contract. They haven’t awarded one yet, so no one’s quite sure how that’s going to work, but they have created a structure for all five types. So far, we have seen them use and award concessions, production-sharing contracts and joint-venture type awards. Pemex also recently awarded a new service contract structure. I would use that as an example of a jurisdiction that has created and is actually using multiple types of awards.
As for other jurisdictions, Tanzania, for example, now has a law that says, we can use a production-sharing contract, but if we want to, we can use other types of contracts as well. These jurisdictions tend to stick with the production-sharing contract, which is widely used in Africa. I can think of only three states in Africa that don’t use a production-sharing contract. That would be South Africa and Namibia, which use concessions, and Ghana, which uses a joint venture.

We’ve seen the rise of the issue of local content over the past decade. Is that discouraging for private investment? How do you advise your clients about local content?
I think there are three things that investors must have if they’re going to be satisfied with an investment arrangement: the right to monetise, stability and enforceability of their legal contracts. There are seven things that a state must have: a fair fiscal share, prompt exploration activity, suitable environmental controls, the requirement to use local goods and services, and to hire local personnel, to train local personnel, and a reasonable degree of control over where and when activities occur.
Local content comprises three of these key attributes that states must have: that local goods and services are utilised, and that local personnel are employed and trained. If a petroleum regime does not address the three needs of investors and the seven needs of states, that investment in that jurisdiction is not durable.
I therefore say to states, “You should have a local content regime, because if you don’t, at some point, people in your country, or your own government, will become unhappy.” I say to investors, “You should be satisfied with a state that has a good set of local content rules because that will make your investment more durable.”

What elements are key in designing an effective local content regime?
I did a survey about 10 years ago of local content provisions in 80 countries around the world, and most of them had a local content provision that reads like this: “The investor will buy local goods and services so long as they are competitive in regard to price, quality, time of delivery and quantities available.” This was thought to be the local content requirement.
My view is it doesn’t work because what such a provision essentially means is the foreign investor will only buy local goods if they are at the best price. If he can find an international supplier at a lower price, he’ll use that. If the local goods are at the best price and foreign goods can be obtained at a better quality, then he’s entitled to buy the foreign goods, despite the fact that they are not the best price. If they’re the best price and the best quality, but the local supplier doesn’t have the quantities available, then the international buyer can choose a foreign supply. If they are the best price, the best quality, and in the numbers available, but can’t be delivered as quickly as a foreign supply, then the international can prefer the foreign supply.
In other words, it’s a failure clause. You would only buy local goods under such a provision if they were the best available, and you’d buy them anyway under those circumstances.
Consequently, many states have now developed local content rules that do a better job of ensuring local supplies, local employment, and so on. I like Brazil’s, for example. Some states have established quotas that are too high and those kinds of local-content requirements establishing employment quotas for local nationals can actually be a disincentive to invest.
Let’s remember that every local content system does have a cost to the state and so it’s important that a state designs a regime that is reasonable in regard to what local content is actually available. In Brazil, when they took away Petrobras’ monopoly on oil rights, they then knew that they liked Petrobras because it bought local goods and services as the state oil company.
They applied a requirement to all investors that they must also buy local goods and services and they asked Petrobras, “How much local content do you buy in your investment activities?” Petrobras gave the relevant ratios for exploration activities, development activities and production activities, and those were then applied to all investors. In other words, they used a logical-empirical standard.
Some jurisdictions in Africa haven’t done it that way and I think they suffer as a result. One of the things that’s unique about even well-designed local content requirements is that they dismiss what is the best price as a measure of what goods you should acquire. Basically, they say, “You must have at least 35% Brazilian content.” Consequently, in certain types of activities, the only people that can effectively bid for the work would be Brazilian suppliers.
Maybe there’s a lesser price supply somewhere else in the world, but an investor in Brazil, bound by the local content rules, knows he needs to buy a Brazilian supply if he’s going to meet the local content rules.
Therefore, let’s assume, in some cases at least, that supply will come at a higher price and the consequences of that impact the state. If you’re in a higher-cost environment, that makes the exploration and development results not as profitable, and so if you tax oil and gas companies based on their profits, that’s going to have a negative impact, and if you use a production-sharing contract, where the state bears part of the cost of the activity, that state’s also bearing that higher cost in a more direct way.

What is the outlook for international oil and gas investment?
I go back to the three things that investors are looking for: the right to monetise, stability and enforceability of their legal contracts. The right to monetise means that they know that when they make a discovery of oil and gas that they will be able to turn it into money. There are many steps between discovery and having money. You need to discover, appraise, declare commercial, develop, produce, gather, process, transport, market and export. Each of those verbs I just mentioned is another opportunity for a state to step in and regulate, restrict or control those activities.
Consequently, what investors want to know is: Do you have a regime in which the ability to get a discovery of oil and get it into the marketplace is available to them? That usually means that someone else has trodden this path ahead of them many times. Therefore, regimes that already have successful examples of production tend to be the most attractive for investment, from the right-to-monetise viewpoint. Jurisdictions that don’t have that have to work extra hard to be attractive.
The second is stability. Investors are looking for commitments on the part of various states that they won’t change the rules of oil and gas investment, in particular royalties and taxes, during the period of the investment. Rules about that vary quite widely. Some jurisdictions do offer fiscal and investment stability guarantees.
Sometimes these are offered on a state-to-state basis through bilateral investment treaties, sometimes through multilateral investment treaties, and sometimes there’s no fiscal stability at all, but a state has such a long history of not expropriating rights, that people are comfortable investing there. The United States is a good example of that. There’s no fiscal stability provision in the United States, but people are investing in oil and gas there on a continued basis, without any real fear that the government’s going to take over those rights.
The final question is that of the enforceability. What we’ve discovered is that in most jurisdictions around the world, local courts are not fair arbiters of a dispute between the local government and a foreign investor. There’s a home-field advantage. Therefore, in foreign investment into oil and gas, and other types of long-term investment industries including mining, using foreign-international arbitration as a means of resolving disputes is vastly preferred. In fact, some companies won’t invest unless they know they have access to those rights.
Those are the three things that I look for in order for a jurisdiction to be attractive to oil and gas investment, legally speaking. You need to layer on top of that which place has good geology and good fiscal terms, and then you’ve got the whole package.

What are some examples of places where investors should be looking right now?
Mexico is one of the places I like. Argentina is another one. Ghana is doing all the right things, in my opinion. Guyana also appears to be attractive.
I have been working in Senegal recently. My sense is that they have the right attitude towards investment there, but they’re at a very sensitive time, as discoveries are about to be developed. This will be an interesting test period because that’s when many jurisdictions start to change the rules a bit. I would say Senegal is attractive for investment and then we’ll see whether or not those investments turn into producing projects sometime soon.
The reason that oil companies care about the right to monetise, stability and enforceability is because of something called the problem of the obsolescing bargain. Let me describe it this way: At the time an oil and gas company makes an investment, that is the point in time at which they have their greatest bargaining power. They have the money, technology and personnel, and the states are saying, “Please, come and invest.”
Once that money has been spent in an exploration project and a discovery has been made, all of a sudden, the bargaining power shifts. It shifts to the state because the state now sees a successful investment and the prospect that the investor is going to do very nicely. The state now has all these other tools of changing the tax regime and the royalty regime, controlling the pace and amount of development, and access to markets, that permit the state to potentially affect the success of the investor’s investment.
There’s a long history around the world, not just in oil and gas but in any long-term investment project, of states changing the rules at this point. I like to develop what I call a report card for oil and gas investment – and I will only give letter grades on my report card to a regime that has gone through the full cycle of explore, develop, produce and even abandon, to see the full investment cycle happen. In the case of Senegal, because it hasn’t gone through a full cycle yet, I’m only prepared to give pass-fail grades, and there’s no doubt that Senegal gets a pass in all key areas.

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